Note: Descriptions are shown in the official language in which they were submitted.
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Initiation of lightweight flexible pipelines and umbilicals
This invention relates to subsea laying of elongate flexible products such as
lightweight
flexible pipelines and umbilicals. The invention relates particularly to the
initiation of
installation operations.
Pipeline installation will be used to exemplify the invention in the following
discussion.
However, it should be understood that the broad inventive concept extends to
subsea
laying of other lightweight elongate flexible products or elements, such as
umbilicals.
To facilitate the initiation of pipelay, a subsea anchor must be preinstalled
to provide a
fixed point for a pipelay vessel to act against during the pipe pulling
process. An
example of a subsea anchor is a pile embedded in the seabed; other examples
are an
anchor held by its weight and/or by friction or engagement with the seabed,
subsea
structures such as templates, platform foundations and so on.
Initiation rigging is typically preinstalled with, and attached to, the
anchor; this rigging
typically comprises a wire rope of fixed length, although it could comprise a
chain. A
first portion of the initiation rigging may be preinstalled with the anchor
and a second
portion of the initiation rigging may be lowered with the pipeline to be
connected to the
first portion.
The 'initiation' stage of a pipeline installation operation typically involves
the steps of:
deploying and lowering a termination head toward the seabed, at the end of a
pipeline
extending from a pipelay vessel to the termination head; connecting the
termination
head to the initiation rigging anchored to the seabed; and laying the
termination head
and the adjoining section of the pipeline down on the seabed.
Initiation may also involve creating a tie-in loop in the pipeline for the
termination head
to be connected subsequently to a subsea structure, where the pipeline is laid
in a
curved (for example, serpentine) configuration after the termination head has
been
landed. Expansion loops are used to provide for controlled displacement of the
pipeline
with fluctuations in temperature and pressure so as to limit forces
transferred to tie-in
structures.
The initiation stage is to be distinguished from the subsequent 'normal lay'
stage of a
pipeline installation operation, as initiation suffers from particular
problems that the
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present invention aims to address. For example, the normal lay stage can use
the full
layback range of the pipeline and so can be performed under correspondingly
high sea
states, whereas the initiation stage cannot.
As the normal lay stage cannot start until the initiation stage has been
completed, the
initiation stage is a key limiting factor in a pipeline installation
operation. Problems
affecting the initiation stage therefore have a disproportionate effect on the
pipeline
installation operation as a whole.
The initiation sequence is performed in steps of paying out product and moving
the
installation vessel after connecting up the initiation rigging between the
termination
head and the anchor point. The governing design criteria are typically found
to be:
pipeline limiting curvature, expressed as the minimum bend radius or MBR;
pipeline departure angle at hang-off, to avoid contact with the hull of the
pipelay
vessel and/or over-bending of the pipeline;
seabed clearance before landing the termination head, to avoid damaging the
termination head;
the landing angle of the termination head, to avoid over-bending or
compression; and
horizontal bottom tension when laying tie-in loops after landing the
termination
head.
As noted above, the initiation stage is often limited by pipeline curvature,
expressed as
the MBR of the pipeline. There is a risk of over-bending the pipe after
initial touchdown
of the termination head occurs, especially at the end of a bending restrictor
commonly
provided at the interface between the flexible pipeline and the rigid
termination head;
there is also a risk of damage to the termination head itself. To limit these
risks, the
termination head and the adjoining section of pipeline are required to be as
close as
possible to parallel with the seabed before touchdown. If water depth and
pipeline
bending stiffness allow, this is achieved by extending the pipeline
configuration
horizontally and forming a sag bend.
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When establishing the lay configuration for a pipeline, the following
parameters are
typically used to control the initiation operation: anchor point elevation
above the
seabed; initiation rigging length; deployed length of pipeline; and position
of the
installation vessel.
Optimally, the subsea anchor point to which the initiation rigging is attached
should be
as high above the seabed as possible to help with levelling of the termination
head and
the adjoining section of pipeline: ideally the anchor point should be at an
elevation of
say 2 to 5 metres above the seabed. If the anchor point is close to the
seabed, longer
initiation rigging is regarded as the better option. In practice, however,
various
restrictions may thwart this optimal configuration.
The elevation of the anchor point and the length of the initiation rigging are
typically
dictated by an existing seabed layout, and may not be optimal for the
initiation
operation. In other words, the seabed layout may restrict the length of the
initiation
rigging and may also dictate an anchor point undesirably close to the seabed;
for
example, an elevation above the seabed of approximately 0.5 metre. Other
disadvantageous factors are: relatively high product bending stiffness; a
heavy
termination head; shallow water depth; and a restriction in the pipeline
departure angle
from a pipelay vessel leading to a risk of over-bending at the hang-off point.
A heavy, robust but flexible pipeline with a lightweight termination head is
the optimal
combination, which in principle could be initiated without any form of
installation aid.
Conversely, the combination of a lightweight but relatively stiff pipeline
such as an ISU
or integrated service umbilical with a heavy termination head is a challenging
combination often resulting in a landing angle that is too steep and so
requires some
form of installation aid. The need for an installation aid increases if it is
not possible to
increase the anchor point elevation or to lengthen the initiation rigging
length to allow a
sag bend to form before landing the termination head.
These challenges result in the need for ancillary equipment to level the
termination
head and the adjoining section of pipeline during the initiation stage. The
traditional and
well-proven method is to use subsea buoyancy modules of typically 1 to 2
tonnes
nominal buoyancy, connected to the termination head using slings. In this
respect,
reference is made to Figures 1 and 2 of the accompanying drawings, in which
Figure 1
shows, schematically, a known pipeline initiation operation employing one or
more
buoyancy modules and Figure 2 shows known buoyancy modules that may be used in
that operation. Figure 1 is a schematic view and is not to scale.
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Referring particularly to Figure 1, this shows a lightweight flexible pipeline
10 hanging
in the water column, suspended from a pipelay vessel that is omitted from this
view. A
termination head 12 is at the end of the pipeline 10.
A subsea anchor 14 such as a pile is embedded in and extends above the seabed
16.
A wire rope serving as initiation rigging 18 is attached to the anchor 14 at a
position
above the seabed 16 and extends from there to the termination head 12. The
termination head 12 and the pipeline 10 attached to it may therefore pivot
about the
anchor 14 via the initiation rigging 18.
A buoyancy module 20 also shown in Figure 2 is attached to the termination
head 12
by a sling 22 to apply upward supporting force to the termination head 12.
Commonly
more than one such module 20 will be used but only one module 20 is shown in
Figure
1 for simplicity. This upward force near the end of the pipeline 10 imparts a
sag bend
24 in the pipeline 10 and brings the termination head 12 and the adjoining
section 26 of
the pipeline 10 closer to the horizontal. The relatively horizontal
orientation of the
termination head 12 and the adjoining section 26 of the pipeline 10 helps to
reduce the
bending stresses that tend to arise between the flexible pipeline 10 and the
rigid
termination head 12 upon touchdown.
Whilst Figure 1 shows the operation after the termination head 12 has been
attached to
the initiation rigging 18, the buoyancy modules 20 are attached to the
termination head
12 earlier in the operation, typically at the surface or on the installation
vessel.
It is relatively easy to lift the termination head 12 with buoyant forces in
this way,
controlling levelling and landing the termination head 12 and the adjoining
section 26 of
the pipeline 10 safely on the seabed 16. However, deployment and retrieval of
the
subsea buoyancy module(s) 20 affects the schedule of the operation and
increases its
risk. Also, due to the dynamics of the system, the limiting sea state for
performing the
initiation operation is often low.
Another significant issue is that tie-in loops must often be laid within tight
tolerances
after the termination head 12 has been landed. This task is limited by the
horizontal
bottom tension or lateral restriction force, and sets limitations on the
layback which in
turn results in a low limiting operational sea state. This may result in
expensive waiting
on weather, reduces the choice of suitable installation vessels and also
increases the
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risk level of the operation. Also, use of temporary turn points may be
necessary, adding
vessel time before and after the initiation operation.
It is against this background that the present invention has been made.
5
In one sense, the invention resides in a method of initiating laying of an
elongate
flexible product on the seabed, comprising tensioning the product between an
anchored termination head and an installation vessel, while imparting a sag
bend
curvature to the product by weight added locally to the product at a sag bend
region, to
orient the termination head and a section of the product adjoining the
termination head
toward the horizontal while they remain above the seabed.
In another sense within the same inventive concept, the invention resides in
various
subsea arrangements arising at different stages of the initiation process.
One such subsea arrangement for initiating laying of an elongate flexible
product on
the seabed comprises: a termination head at an end of the product; an anchor
to which
the termination head is attached; and weight added locally to the product at a
sag bend
region that imparts a sag bend curvature to the product to orient the
termination head
and a section of the product adjoining the termination head toward the
horizontal while
they remain above the seabed.
Another such arrangement comprises: a termination head at an end of the
product and
an anchor to which the termination head is attached, the termination head and
an
adjoining section of the product being laid on the seabed while a weighted sag
bend
region remains above the seabed, weight being added locally to the product at
the sag
bend region to impart a sag bend curvature to the product.
Another such arrangement comprises: a termination head at an end of the
product and
an anchor to which the termination head is attached, the termination head, an
adjoining
section of the product and a weighted sag bend region of the product being
laid on the
seabed, weight being added locally to the product at the sag bend region. The
product
may be laid on the seabed in a curved configuration when viewed from above, in
which
case the weighted sag bend region is preferably part of the curve.
The added weight may be distributed along the sag bend region of the product,
for
example by being disposed at a plurality of discrete locations spaced along
the sag
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bend region. Alternatively the added weight may be disposed along a continuous
length of the product extending along the sag bend region. In that case, the
added
weight may comprise segments in mutual contact along the continuous length of
the
product.
The section of the product adjoining the termination head suitably spaces the
sag bend
region from the termination head.
Weight may be added to the product by attaching one or more weight modules to
the
product at the sag bend region, in which case the or each weight module and/or
the
product preferably has grip-enhancing formations for engaging the seabed. Such
weight modules are suitably attached to the product on the installation vessel
or before
the product is loaded onto the installation vessel.
It is possible for the added weight to be incorporated into the product as
manufactured.
For example, the added weight may be defined by one or more sections at the
sag
bend region where the product is enlarged, thickened or of increased density.
The termination head is suitably anchored by initiation rigging extending to a
subsea
anchor, and may then be supported above the seabed by tension between the
product
and the initiation rigging. By means of the invention, the termination head is
preferably
supported above the seabed without added buoyancy.
In summary, therefore, the invention contemplates the use of added ballast as
an
installation aid for initiating lightweight elongate products such as flexible
pipelines and
umbilical cables, as an alternative to the traditional method of using added
temporary
buoyancy modules. The installation of the ballast can often be performed
before
connecting up to the initiation anchor point, and hence can be performed away
from
adjacent lines on the seabed, or in close vicinity to platforms or other
structures.
The added ballast is preferably permanently mounted to or integral with the
product, to
remain with the product after the product has been laid on the seabed. This
reduces
the time and risk involved in retrieving subsea buoyancy modules.
The invention may employ distributed ballast modules or a continuous length of
added
weight to aid initiation. This helps to level the termination head by adding
weight in the
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region of the sag bend. The added weight also improves the dynamic response of
the
system, resulting in a higher limiting sea state for performing the operation.
The distributed or continuous added weight of the invention improves the tie-
in
operation in most cases by giving the product a higher submerged weight. After
the
section of the elongate product adjoining the termination head has landed on
the
seabed, the added weight and increased friction between the product and the
seabed
enables a larger layback when laying a curve such as a tie-in loop, making it
easier to
install the product in a curved configuration and increasing resistance of the
product to
lateral sliding across the seabed. This also increases the limiting sea state
for
performing the operation, compared to traditional pipeline initiation methods
that use
added buoyancy.
The added weight and increased seabed friction increases natural hold-back
forces,
hence avoiding temporary turn points and reducing the need for an extra hold-
back
winch often used when pulling-in during a tie-in operation.
Advantageously, by virtue of the invention, tie-in loops can be tighter in
radius, more
accurate in position and start closer to the termination head.
Friction between the product and the seabed can be increased by using grip-
enhancing
formations such as a serrated outer wall on the pipeline and/or on ballast
modules
attached to the pipeline.
Ballast attached to the pipeline also helps to protect and insulate the
installed pipeline.
The invention therefore aims to reduce or eliminate the need for an additional
buoyancy element when initiating lightweight flexible pipelines towards a
subsea
anchor point as well as increasing the operational sea state for laying the
subsequent
tie-in loops. This reduces the risk of expensive waiting on weather, increases
the
choice of suitable installation vessels and also increases the safety level of
the
operation.
The traditional pipeline initiation method described previously with reference
to Figures
1 and 2 may still be preferred where the maximum hang-off load is limiting,
and the tie-
in loops and pull-in operation are not limiting. The alternative pipeline
initiation method
provided by the invention is preferred when the introduction of a buoyancy
module
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reduces the limiting sea state, and tie-in loops are challenging to achieve
due to factors
including light weight of the product; high bending stiffness of the product,
or low
friction between the product and the seabed.
Reference has already been made to Figures 1 and 2 of the accompanying
drawings to
explain the prior art, where:
Figure 1 is a schematic side view of a pipeline initiation operation known in
the
art, after attachment of a termination head to initiation rigging; and
Figure 2 is a perspective view, on land, of buoyancy modules that may be used
in the prior art operation of Figure 1.
In order that the invention may be more readily understood, reference will now
be
made, by way of example, to the remaining drawings in which:
Figure 3 is a schematic side view of a pipeline initiation operation in
accordance
with the invention, with distributed ballast modules attached to the pipeline
in
the region of the sag bend;
Figure 4 is a schematic perspective view of a pipeline laid on the seabed as
part of a pipeline initiation operation in accordance with the invention,
again with
distributed ballast modules, showing the pipeline laid in a curved
configuration
when viewed from above;
Figure 5 is a schematic side view of a pipeline initiation operation in
accordance
with the invention, in a variant with a continuous ballast module attached to
the
pipeline in the region of the sag bend;
Figure 6 is a schematic part-sectional side view of a pipeline initiation
operation
in accordance with the invention, in a further variant where the pipeline has
a
section of thickened wall to increase weight locally in the region of the sag
bend;
Figures 7a and 7b are snap-shots from computer simulations of system
behaviour at an early stage of the initiation process, which compare the prior
art
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system shown in Figure 7a with the system of the invention shown in Figure 7b
under the same sea state; and
Figures 8a and 8b are snap-shots from computer simulations of system
behaviour at a later stage of the initiation process, which compare the prior
art
system shown in Figure 8a with the system of the invention shown in Figure 8b
under the same sea state.
Reference will also be made, by way of example, to the appended Table 1, which
shows the effect of added weight upon limiting horizontal tension for a given
lay radius.
Referring firstly to Figure 3, this corresponds partially to Figure 1 and like
numerals are
used for like features. As before, a lightweight flexible pipeline 10 hangs in
the water
column, suspended from a pipelay vessel 28, with a termination head 12 at its
lower
end. A pile serving as a subsea anchor 14 is embedded in and extends above the
seabed 16. A wire rope serving as initiation rigging 18 is attached to the
anchor 14 at a
position above the seabed 16 and extends from there to the termination head
12, such
that the termination head 12 and the pipeline 10 may pivot about the anchor 14
while
tension is applied between the anchor 14 and the pipelay vessel 28 via the
pipeline 10
and the initiation rigging 18.
Before reaching the position shown in Figure 3, the termination head 12 and
the
pipeline 10 attached to it are launched from the pipelay vessel 28 before
being coupled
to the anchor 14 via the initiation rigging 18, typically using an ROV. After
that, the
termination head 12 and the pipeline 10 are landed on the seabed 16; the
pipeline 10
may be landed in a curved configuration, as Figure 4 will show, to form a tie-
in loop.
In accordance with the invention, at least one and preferably all of the
buoyancy
modules 20 shown in Figures 1 and 2 are rendered unnecessary by the addition
of
weight to the pipeline 10. The added weight also helps to protect the pipeline
10, by
providing localised impact and abrasion resistance.
In the variant shown in Figure 3, the added weight is provided by ballast
modules 30
permanently mounted to and distributed along a section of the pipeline 10 in a
region
close to, but spaced from, the termination head 12. The combined,
longitudinally
spread, downward weight forces of the ballast modules 30 impart the desirable
sag
bend 24 to the pipeline 10.
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The added weight at the sag bend 24 brings the termination head 12 and the
adjoining
portion 26 of the pipeline 10 closer to the horizontal to reduce bending
stresses
between the pipeline 10 and the termination head 12 upon touchdown. It will be
noted
5 that the termination head 12 and the adjoining portion 26 of the pipeline
10 are oriented
substantially closer to the horizontal than a section of the pipeline 10
immediately
above the sag bend 24.
The gap between the ballast modules 30 and the termination head 12 also helps
to
10 reduce bending stresses in the portion 26 of the pipeline 10 adjacent to
the termination
head 12.
Whilst Figure 3 shows the pipeline initiation operation after the termination
head 12 has
been attached to the initiation rigging 18, the ballast modules 30 are
attached to the
pipeline 10 earlier in the operation, typically on the installation vessel.
In addition to levelling the termination head 12, the ballast modules 30
reduce the
departure angle of the pipeline 10 by changing its configuration. The added
weight in
the system improves its dynamic behaviour and increases the resistance of the
pipeline
10 to lateral sliding across the seabed 16 when laying tie-in loops, thus
increasing the
allowable sea state for the start-up phase or initiation stage of the
installation. There is
also a reduced need for a hold-back winch during a pull-in operation.
The ballast modules 30 may, for example, comprise Duraguard HD (high density)
modules supplied by Balmoral Offshore Engineering of Aberdeen or Uraduct
modules
supplied by Trelleborg Offshore of Stavanger. An alternative is to use
Polyspace
modules also supplied by Trelleborg Offshore with a ballast system to provide
additional submerged weight. 'Duraguard', 'Balmoral', `Uraducf, `Polyspace'
and
Trelleborg' are acknowledged herein as trade marks.
The Duraguard system was developed for the protection of subsea cables,
flexible
jumpers, flexible flowlines and riser touchdown zones to provide localised
impact
resistance and abrasion protection. Its polyurethane modules are supplied as
pairs of
interlocking half shells secured around the core product using circumferential
straps. A
ballasted variant is used in ballast or stabilising systems, with heavy filler
materials
added to the polyurethane mix to increase density and hence overall weight.
The
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ballast adds on-bottom stability and reduces the risk of clashing between
adjacent
lines.
Duraguard modules can be fitted during unreeling/laying or before reeling.
Adjacent
segments with overlapping ends may be added to provide a continuous protected
and
ballasted length.
The Uraduct system has been used on fibre-optic cables, power and umbilical
cables,
flexible and rigid flowlines, hoses and bundled products, particularly where
additional
protection is required, such as on a rocky seabed, at touchdown locations, at
shore
landings and at cable or pipeline crossings. It is an alternative to known
protection
methods such as rock dumping or concrete mattressing.
Like Duraguard, Uraduct comprises cylindrical half-shells moulded from
polyurethane.
The half-shells overlap and interlock around the core product and are secured
in place
using corrosion-resistant bands. For ease of handling and transportation,
Uraduct
modules are manufactured in lengths of up to two metres with flexing
characteristics to
suit the required minimum bend radius of the product or ancillary shipboard
lay
equipment.
High-density polyurethane with a specific gravity of 2.3g/cm3 (offering an in-
water
weight equivalent to concrete) may be used where additional stability is
required, for
example where cables will be exposed to strong seabed currents and so
additional
weight will be beneficial. A super-heavyweight Uraduct variant combines
polyurethane
with the added weight of lead inserts encapsulated in each half-shell during
moulding.
The ratio of lead to polyurethane can be varied to give an average specific
gravity in
excess of 3.0g/cm3.
Polyspace is a product designed to maintain a positive clearance between
cables and
existing pipelines at crossing points. Alternative methods such as pre-lay
rock
dumping, concrete mattressing and steel structures are expensive, time
consuming
and difficult to place accurately.
Again, Polyspace modules comprise interlocking half-shells fastened around the
cable
by bands as the cable is deployed from an installation vessel at a crossing
location. In
this case, the half-shells are manufactured from UV-stable, marine grade, high
density
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polyethylene. Each moulding is free-flooding and can be supplied with a
ballast system
to provide up to 90kg/m3 of additional submerged weight to suit the
application.
Figure 4 shows the pipeline 10 laid on the seabed 16 in a curved configuration
representing a tie-in loop or expansion loop. Engagement between the seabed 16
and
the pipeline 10 and/or the ballast modules 30 resists lateral sliding of the
pipeline 10
after touchdown, which would deform the loop unpredictably. For example, the
loop
could otherwise tend to straighten under the tension of the normal lay phase
of the
pipelay operation.
Friction between the pipeline 10 and the seabed 16 can be increased to improve
engagement by using grip-enhancing formations such as a serrated or corrugated
outer wall on the pipeline 10 and/or on the ballast modules 30 attached to the
pipeline
10. By way of example, Figure 4 shows corrugations 32 on the ballast modules
30, the
corrugations 32 being oriented longitudinally to resist lateral sliding of the
pipeline 10
across the seabed 16. Other orientations and grip-enhancing configurations are
possible.
The variants shown in Figures 5 and 6 largely correspond to Figure 3 but show
that the
added weight need not comprise discrete spaced modules but could instead
comprise
a continuous section. The variant in Figure 5 employs a single elongate
tubular ballast
module 34 attached to the pipeline 10 and extending along its sag bend region.
The
ballast module 34 is preferably flexible and it need not be in a single piece:
it may be
segmented or articulated, for example comprising overlapping or interlocking
Duraguard modules as described above. Conversely the variant in Figure 6 adds
weight to the pipeline 10 by virtue of a thickened wall portion 36 extending
along its sag
bend region. Again, grip-enhancing formations may be provided on the elongate
ballast
module 34 or on the thickened wall portion 36, although such formations are
omitted
from Figures 5 and 6.
Other variations are possible without departing from the inventive concept.
For
example, it may be appropriate to shape the sag bend 24 by varying the
effective
weight per unit length of the pipeline 10 along the length of the sag bend 24.
Where
discrete ballast modules 30 are used as in Figure 3, the ballast modules 30
need not
be of the same weight; nor do they have to be equally spaced from each other.
It would
therefore be possible to vary the spacing between the ballast modules 30 or
their
relative weights. It would also be possible to achieve a similar effect in the
variants
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shown in Figures 5 and 6, for example by varying density along the length of
the
elongate tubular ballast module 34 of Figure 5 or by varying wall thickness
along the
length of the thickened wall portion 36 of Figure 6.
Moving on now to Figures 7a and 7b, these are 'snapshots' taken from two
simulations
with the same sea state. Figure 7a illustrates a prior art system with modular
buoyancy
to lift the termination head, whereas Figure 7b illustrates a system in
accordance with
the invention having distributed weight to lower the sag bend. In both cases,
the
termination head and the pipeline have been attached to initiation rigging but
have not
yet been landed on the seabed.
A regular wave with height of 8.0 metres and period of 6.5 seconds is
introduced to the
model, applied 30 degrees off head seas. The starting or static stage is
similar for the
two systems, i.e. with the termination head just 1.0 metre above the seabed.
This step
in the initiation process is normally governed with reference to over-bending
at the
hang-off, or alternatively violating a departure angle criterion.
As can be seen, the system of Figure 7a including a buoyancy module introduces
a
larger dynamic response of the termination head. Snap forces are observed in
the
initiation rigging, and the product experiences over-bending at the end of the
bend
restrictor section adjoining the termination head. In contrast, the
configuration of Figure
7b gives far better dynamic response than the configuration of Figure 7a and
does not
violate any of the assumed criteria.
The maximum departure angle in the prior art system of Figure 7a is
approximately
eighteen degrees, which is three degrees more than the system with distributed
weight
of Figure 7a in accordance with the invention.
The conclusion from the comparison between Figures 7a and 7b is that the prior
art
system with modular buoyancy will have a much lower limiting sea state than
the
system of the invention with added ballast. By virtue of the invention, an
increase in the
limiting sea state of approximately 25%-30% is expected for this stage of the
initiation
operation.
Later in the initiation operation, maximum curvature is traditionally observed
when the
back end of the bend restrictor section is to be landed on the seabed. This
phase is
illustrated in Figures 8a and 8b for the same two systems as shown in Figures
7a and
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7b, in the same sea state, again with modular buoyancy and with added weight
respectively.
Again the system of the invention with added weight shown in Figure 8b fares
better
than the prior art system with modular buoyancy shown in Figure 8a. It is
noted in
Figure 8a that the prior art system with modular buoyancy violates the
curvature
criterion, just aft of the bend restrictor section. The system of the
invention with added
weight shown in Figure 8b has a much better dynamic response, and there is no
violation of the curvature criterion. The departure angle is also less extreme
for the
weighted system of the invention. The conclusion from a comparison between
Figures
8a and 8b is that the weighted system of the invention is installable in the
sea state on
which the model is based, while the traditional system using a buoyancy module
needs
a reduced sea state. The difference between the allowable sea states is
assumed to be
in the range of 25%-30%, or more, in favour of the weighted system of the
invention.
The systems of the invention modelled in Figures 7b and 8b have not been
optimised
with respect to the location and the amount of added weight. They simply
illustrate the
differences and investigate the effects of having a weight section in the
system.
To have a significant effect on the configuration, it is anticipated that a
considerable
length of added weight will be needed with a relatively large mass per unit
length.
However, the touchdown tension is about three times higher for the weighted
system of
the invention compared to the traditional system with modular buoyancy. This
also
means that there will be higher forces in the initiation rigging. A stronger
anchor point is
therefore required, which may limit the amount of weight to be added. The
increased
load in the initiation rigging and the increased hang-off load may restrict
the use of the
method of the invention to cases where it is difficult to achieve a reasonable
limiting
sea state with the traditional initiation method using modular buoyancy.
Evaluation of lateral curve stability is necessary to ensure that planned
curves can be
accommodated during installation of a pipeline. Possible restrictions in
layback and/or
limiting sea state need to be established in order to keep the touchdown
tension low
enough to avoid the pipeline sliding laterally out of the planned lay
corridor. If a curve is
found to be impractical to achieve due to operational restrictions, the
requirements for
turn points need to be established.
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Various methods are available for calculating the minimum curve radius, or the
maximum horizontal bottom tension (touchdown tension) with increasing
complexity,
such as the inclusion of passive soil resistance or seabed mechanics. However,
for
comparison purposes, a simplified relationship between the tension, radius,
submerged
5 weight of pipeline and lateral seabed friction may be used.
Table 1 shows the effect of added weight upon limiting horizontal tension for
a given
lay radius and lateral friction factor. In Table 1, the curve radius is
assumed to be fixed
to 40 metres as a typical tie-in loop radius and minimum route curve radius,
and the
10 effect of added ballast is investigated by increasing the submerged
weight. The results
illustrate the added value of the weighted section, and clearly depict how the
increased
submerged weight increases the operability for curve lay by increasing the
limiting
horizontal tension prior to sliding.
15 In practice, the lateral friction factor and the passive soil resistance
will also increase,
thus further increasing the limiting horizontal bottom tension due to the
increase of
submerged weight by using weight modules. The weighted section will increase
the
minimum layback (governed by the curvature at the touchdown region) and hence
the
static touchdown tension. However, this increase is less than the increase of
limiting
horizontal bottom tension for curve lay. It is therefore possible to lay the
curve in a
higher sea state without increasing the risk of excessive lateral
displacement.
The increase of limiting horizontal bottom tension before sliding reduces the
need for
turn points in case of tight turns. Further, the allowable sea state will
increase due to
the weighted section, hence reducing the risk of costly vessel standby time
due to
waiting on weather during installation.
Clearly, there will be some extra time involved in mounting weight modules on
the
pipeline during initiation or normal lay compared to not using weight modules
at all,
although this need not adversely affect the critical path. However, the
possibility of
installing the pipeline in higher sea states instead of waiting on the weather
will in many
cases be the preferred option. The invention also reduces or eliminates the
need for
added buoyancy attached to the termination head and so reduces or eliminates
the
time and risk necessary to attach and to remove buoyancy modules.
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16
9/9
Type of Lay radius Lateral Submerged
Limiting
pipeline (m) friction factor weight horizontal
H (N/m)
tension
(kN)
Bare pipe 40 0.5 115 2.300
+100 kg/m 40 0.5 1096 21.920
+200 kg/m 40 0.5 2076 41.520
Table 1
